The present invention relates to a method of enhancing recovery of petroleum from an oil bearing formation.
In the recovery of light oils (i.e., greater than 20.degree. API) from reservoirs, particularly deep, high pressure reservoirs which are composed of sandstone, the use of primary production techniques (i.e., use of only the initial formation energy to recover the crude oil), followed by the secondary technique of water flooding, recovers only about 60 to 70% of the original oil present in the formation.
Moreover, the use of certain enhanced oil recovery (EOR) techniques is also known within the art. These techniques can be generally classified as either a thermally based recovery method, i.e., utilizing steam, or a gas-drive method that can be operated under either miscible or non-miscible conditions.
The gases which are commonly employed in gas-drive methods are those normally referred to as non-condensible gases, for example, nitrogen, carbon dioxide, methane, mixtures of methane with ethane, propane, butane, and higher hydrocarbon homologues.
Although the viscosity of these lighter oils is comparable to that of water, the use of steam-based EOR techniques is usually not found to be practical or economical because these types of oil are found at depths requiring pressures greater than 1000 psi to force the oil to flow. For this reason, the art has primarily focused upon the gas-drive methods employing noncondensible gases such as hydrocarbons, N.sub.2 or CO.sub.2 in this environment.
For a given crude oil and temperature, the non-condensible gases become miscible with the oil above a pressure known as the minimum miscibility pressure. Above this pressure, these "noncondensible" gases attain a supercritical state wherein their behavior has characteristics of both gases and liquids.
With those enhanced recovery processes which employ noncondensible gases under miscible conditions, the oil can be caused to flow toward a producing well because the noncondensible gas "swells" the oil (i.e., increases the volume by dissolving in the oil) and, thus, reduces the viscosity of the oil.
The method of the present invention is preferably directed to this miscible operation although it is equally effective under non-miscible conditions.
A typical procedure involves injecting a slug of CO.sub.2 followed by the injection of a higher viscosity fluid such as water to "push" the CO.sub.2. See, for example, the discussion in U.S. Pat. No. 2,623,596. Moreover, U.S. Pat. No. 3,065,790 indicates that this process may be more cost effectively employed if a relatively small slug of CO.sub.2 is injected ahead of a drive fluid. In fact, as illustrated by U.S. Pat. No. 3,529,668, this type of recovery procedure is typically performed in "water alternating gas (WAG)" cycles.
Because of the viscosity and density differences between the CO.sub.2 and the light oil (i.e., CO.sub.2 has only 5 to 10% of the viscosity of the light oil), the CO.sub.2 tends to bypass much of the oil when flowing through the pores of the rock reservoir.
One proposed solution to this problem associated with the bypassing of the CO.sub.2 has been through the use of a small amount of water which contains a surfactant, with the CO.sub.2. In particular, a surfactant has been proposed as a means for generating a foam or an emulsion in the formation. See, for example, U.S. Pat. No. 4,380,266 to Wellington and U.S. Pat. No. 5,502,538 to Wellington et al. Each of these foams or emulsions is composed of a non-condensible gas, such as CO.sub.2, and water which contains a surfactant.
The purpose of this foam is to inhibit the flow of the CO.sub.2 into that portion of the formation containing only residual oil saturation. In addition, the foam physically blocks the volumes through which CO.sub.2 is short-cutting. This forces the CO.sub.2 to drive the recoverable hydrocarbons from the less depleted portions of the reservoir toward the production well.
However, as clearly discussed within U.S. Pat. No. 4,380,266, the use of traditional surfactants, such as ethoxy-sulfates (particularly Alipal CD 128 supplied by GAF Corp.), suffers from problems associated with the instability of the foam produced in this environment. In the Society of Petroleum Engineers paper SPE 14394 (Las Vegas, NV, Sept. 22-25, 1985), Borchardt, et. al. summarize evaluation of over 40 surfactants for use in CO.sub.2 foam flooding. Neither their studies nor the extensive literature cited mentions use of alpha olefin sulfonates (AOS). Thus, while certain surfactants have been suggested for use in this manner, the art has been largely unable to provide a foam-forming composition which is effective in providing a stable foam in this environment.
In particular, when using an non-condensible gas under miscible conditions, the creation of an effective foam is very difficult because either the salt concentration of the water in the formation (connate or injected as brine), the residual oil in the reservoir, or the chemical instability of surfactants tend to break the foam or even prevent the foam from forming.
The class of surfactants, known as alpha-olefin sulfonate (AOS) surfactants, is also recognized in the art. See, for example, U.S. Pat. No. 3,332,880 to Kessler et al. These surfactants have been typically employed in detergent compositions for dishwashing and laundering. Such AOS compositions are typically a generic mixture of components such as hydroxy-sulfonates, alkene-sulfonates and alkene-disulfonates and the relation of foam performance to composition has focussed on detergency and dishwashing. This patent specifically claims 4 hydroxy-n-hexadecyl -1- sulfonate as a superior cleaning agent in hot water household laundry use. A companion filing, U.S. Pat. No. 3,488,384 describes processes for preparation of AOS for the generic composition described above.
The art has utilized certain AOS compounds in the thermal steam drive recovery techniques previously discussed. See, for example, U.S. Pat. No. 4,393,937 to Dilgren et al which discusses a steam foam-forming composition which includes AOS compositions. This patent discloses that for steam drive processes, the specific composition of the AOS surfactants employed is not a critical factor.
The use of AOS compositions in steam drive techniques is also illustrated by U.S. Pat. No. 4,532,993 to Dilgren et al. The AOS composition employed within this patent was chosen so as to provide a foam which will collapse in the presence of oil.
It has also been recognized that the relative proportions of the components of the AOS can be varied depending upon the process conditions employed in production of the AOS. For example, it has been recognized that the 3-hydroxy component of the AOS will be minimized and the 4-hydroxy component maximized if the 1-3 sultone intermediate is allowed to age during AOS production and, thus, isomerize into a 1,4-sultone. See, for example, the discussion in Shell Technical Bulletin SC:74-81 by Kubitschek et al.
On the other hand, an AOS composition which has a high concentration of the 3-hydroxy component has been recognized as a possible additive to steam drive foam-forming compositions. See "Analysis of Alpha Olefin Sulfonates Qualitative Carbon-13 NMR" by Gentemkpo, et al., Shell Development Co., 1985.
The possible use of a high molecular weight AOS within a steam drive environment is not particularly surprising because the requirements for effective foaming in steam are related to solubility and foaming ability at high temperatures (i.e., 300 to 600.degree. F. and pressures of 100 to 500 psi). The AOS used in liquid household dishwashing liquid detergents is based on C.sub.14 -C.sub.16 alpha olefins because testing shows this molecular weight range AOS gives optimum foaming at 100-120.degree. F., the temperature range for hand dishwashing.
The requirements are substantially different for miscible gas flooding systems, i.e., these systems utilize temperatures below 200.degree. F. and pressures greater than about 1200 psi for CO.sub.2 and up to about 5000 psi for nitrogen.
Another problem with the use of non-condensible gases such as CO.sub.2 within sandstone reservoirs is the undesirable and uneconomically high adsorption of surfactant onto the sandstone. This is a particular problem with respect to systems which employ non-condensible gases such as CO.sub.2 when compared to steam drive methods, due to the fact that adsorption occurs at much lower levels in the higher temperature environment associated with steam as compared to the relatively low temperatures normally encountered in light oil reservoirs. In other words, adsorption increases as the temperature is lowered.
Thus, the need still exists for a foam forming composition which is effective in providing a stable foam, particularly for use with non-condensible gases such as CO.sub.2 in the removal of light oils from sandstone reservoirs.
Accordingly, it is an object of the present invention to provide an effective method for enhancing recovery of petroleum from oil bearing formations.
It is a further object to provide a foam which can be effectively employed with a non-condensible gas such as CO2 in a method of enhanced recovery of light oil from a reservoir.
These and further objects will become apparent from the specifications and claims which follow.